# Appendix A to the 2015 Supporting Statement for Sub part W

Dated September 2015

New Subpart W Reporting ElementsEmission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionNatural Gas PneumaticDevices§98.236(b)(1)(i) The total number of devices of each type, determined according to §98.233(a)(1) and (2). 1Natural Gas PneumaticDevices§98.236(b)(1)(ii)(A) The number of devices of eachtype reported in paragraph (b)(1)(i) of this section that are counted. 1Natural Gas PneumaticDevices§98.236(b)(1)(ii)(B) The number of devices of eachtype reported in paragraph (b)(1)(i) of this section that are estimated (not counted). 1Natural Gas PneumaticDevices§98.236(b)(1)(ii)(C) If the total number of devicesof each type is an estimated value determined according to § 98.233(a)(2), whetherthe calendar year is the first calendar year of reporting or the second calendar year of reporting1Natural Gas PneumaticDevices§98.236(b)(2) Estimated average number of hours inthe calendar year that the natural gas pneumatic devices reported inparagraph (b)(1)(i) of this section were operatingin the calendar year (“Tt” in Equation W-1).1Natural Gas PneumaticDevices§98.236(b)(3) Annual CO2emissions, in metric tons CO2, for the natural gas pneumatic devices combined, calculated usingEquation W-1 and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section.1Natural Gas PneumaticDevices§98.236(b)(4) Annual CH4emissions, in metric tons CH4, for the natural gas pneumatic devices combined, calculated usingEquation W-1 and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section1Natural Gas PneumaticPump Venting§98.236(c)(1) Count of natural gas driven pneumaticpumps1Natural Gas PneumaticPump Venting§98.236(c)(2) Average estimated number of hours inthe calendar year the pumps were operational (“T” in Equation W-2). 1Natural Gas PneumaticPump Venting§98.236(c)(3) Annual CO2emissions, in metric tons CO2, for all natural gas driven pneumatic pumps combined, calculatedaccording to §98.233(c)(1) and (2)1Natural Gas PneumaticPump Venting§98.236(c)(4) Annual CH4emissions, in metric tons CH4, for all natural gas driven pneumatic pumps combined, calculatedaccording to §98.233(c)(1) and (2)1Acid Gas Removal §98.236(d)(1)(i) Unique name or IDnumber for acid gas removal unit.1Acid Gas Removal §98.236(d)(1)(ii) Total feed rateentering the acid gas removal unit, using a meter or engineering estimate based on processknowledge or best available data, in million cubicfeet per year.1Acid Gas Removal §98.236(d)(1)(iii) The calculationmethod used to calculate CO2emissions from the acid gas removal unit, as specified in§98.233(d).1Acid Gas Removal §98.236(d)(1)(iv) Whether any CO2emissions from the acid gas removal unit are recovered and transferred outside the facility. 1Acid Gas Removal §98.236(d)(1)(iv) If any CO2emissions from the acid gas removal unit were recovered and transferred outside the facility, the annualquantity of CO2, in metric tons CO2, that was recovered and transferred outside the facility.1Acid Gas Removal §98.236(d)(1)(v) Annual CO2emissions, in metric tons CO2, from the acid gas removal unit, calculated usingany one of thecalculation methods specified in §98.233(d) and asspecified in §98.233(d)(10) and (11).1Acid Gas Removal §98.236(d)(1)(vi) Name of the county that best represents the equipment supplying gasto the unit. 1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionAcid Gas Removal §98.236(d)(2)(i)(A) For each unitfor which Calculation Method 1 or 2 in §98.233(d) is used, annual average volumetric fraction ofCO2in the vent gas exiting the acid gas removal unit.1Acid Gas Removal §98.236(d)(2)(i)(B) For each unitfor which Calculation Method 1 or 2 in §98.233(d) is used, annual volume of gas vented from theacid gas removal unit, in cubic feet.1Acid Gas Removal §98.236(d)(2)(ii)(A) For each unitfor which Calculation Method 3 in §98.233(d) is used, which equation was used (Equation W-4A orW-4B).1Acid Gas Removal §98.236(d)(2)(ii)(B) For each unitfor which Calculation Method 3 in §98.233(d) is used, annual average volumetric fraction of CO2inthe natural gas flowing out of the acid gas removalunit, as specified in Equation W-4A or Equation W-4B.1Acid Gas Removal §98.236(d)(2)(ii)(C) For each unitfor which Calculation Method 3 in §98.233(d) is used, annual average volumetric fraction of CO2content in natural gas flowing into the acid gas removal unit, as specified in Equation W-4A or Equation W-4B.1Acid Gas Removal §98.236(d)(2)(ii)(D) For each unitfor which Calculation Method 3 in §98.233(d) is used, the natural gas flow rate used, as specified inEquation W-4A, reported as either total annual volume of natural gas flow into the acid gas removal unit in cubicfeet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal unit, as specified inEquation W-4B, in cubic feet at actual conditions,.1Acid Gas Removal §98.236(d)(2)(iii)(A) For each unit for which Calculation Method 4 in §98.233(d) is used, the name of the simulation software packageused.1Acid Gas Removal §98.236(d)(2)(iii)(B) For each unit for which Calculation Method 4 in §98.233(d) is used, the natural gas feed temperature, in degreesFahrenheit.1Acid Gas Removal §98.236(d)(2)(iii)(C) For each unit for which Calculation Method 4 in §98.233(d) is used, the natural gas feed pressure, in pounds persquare inch.1Acid Gas Removal §98.236(d)(2)(iii)(D) For each unit for which Calculation Method 4 in §98.233(d) is used, the natural gas flow rate, in standard cubicfeet per minute.1Acid Gas Removal §98.236(d)(2)(iii)(E) For each unit for which Calculation Method 4 in §98.233(d) is used, the acid gas content of the feed natural gas,inmole percent.1Acid Gas Removal §98.236(d)(2)(iii)(F) For each unit for which Calculation Method 4 in §98.233(d) is used, the acid gas content of the outlet natural gas,in mole percent.1Acid Gas Removal §98.236(d)(2)(iii)(G) For each unit for which Calculation Method 4 in §98.233(d) is used, the unit operating hours, excluding downtimefor maintenance or standby, in hours per year.1Acid Gas Removal §98.236(d)(2)(iii)(H) For each unit for which Calculation Method 4 in §98.233(d) is used, the exit temperature of the natural gas, indegrees Fahrenheit.1Acid Gas Removal §98.236(d)(2)(iii)(I) For each unit for which Calculation Method 4 in §98.233(d) is used, the solvent pressure, in pounds per squareinch.1Acid Gas Removal §98.236(d)(2)(iii)(J) For each unit for which Calculation Method 4 in §98.233(d) is used, the solvent temperature, in degreesFahrenheit.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionAcid Gas Removal §98.236(d)(2)(iii)(K) For each unit for which Calculation Method 4 in §98.233(d) is used, the solvent circulation rate, in gallons perminute.1Acid Gas Removal §98.236(d)(2)(iii)(L) For each unit for which Calculation Method 4 in §98.233(d) is used, the solvent weight, in pounds per gallon. 1Dehydrators §98.236(e)(1)(i)For each glycol dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4million standard cubic feet per day, a unique nameor ID number for the dehydrator.1Dehydrators §98.236(e)(1)(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimatebased on best available data.1Dehydrators §98.236(e)(1)(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. 1Dehydrators §98.236(e)(1)(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet. 1Dehydrators §98.236(e)(1)(v) Dehydrator absorbentcirculation pump type (e.g., natural gas pneumatic, air pneumatic, or electric). 1Dehydrators §98.236(e)(1)(vi) Dehydrator absorbentcirculation rate, in gallons per minute.1Dehydrators §98.236(e)(1)(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)). 1Dehydrators §98.236(e)(1)(viii) Whether stripper gas is used in dehydrator.1Dehydrators §98.236(e)(1)(ix) Whether a flash tankseparator is used in dehydrator.1Dehydrators §98.236(e)(1)(x) Total time the dehydrator is operating, in hours.1Dehydrators §98.236(e)(1)(xi) Temperature of the wet natural gas, in degrees Fahrenheit.1Dehydrators §98.236(e)(1)(xii) Pressure of the wetnatural gas, in pounds per square inch gauge.1Dehydrators §98.236(e)(1)(xiii) Mole fraction of CH4in wet natural gas.1Dehydrators §98.236(e)(1)(xiv) Mole fraction of CO2in wet natural gas.1Dehydrators §98.236(e)(1)(xv) For each glycol dehydrator that has an annual average daily natural gasthroughput greater than or equal to 0.4million standard cubic feet per day, whether any dehydrator emissions are vented to a vapor recovery device.1Dehydrators §98.236(e)(1)(xvi) For each glycol dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4million standard cubic feet per day, whether any dehydrator emissions are vented to a flare or regeneratorfirebox/fire tubes.1Dehydrators §98.236(e)(1)(xvi)(A) For each glycoldehydrator that has an annual average daily naturalgas throughput greater than or equal to 0.4million standard cubic feet per day, if any emissions are vented to a flare or regenerator firebox/fire tubes, annualCO2emissions, in metric tons CO2, for the dehydrator.1Dehydrators §98.236(e)(1)(xvi)(B) For each glycoldehydrator that has an annual average daily naturalgas throughput greater than or equal to 0.4million standard cubic feet per day, if any emissions are vented to a flare or regenerator firebox/fire tubes, annualCH4emissions, in metric tons CH4, for the dehydrator.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionDehydrators §98.236(e)(1)(xvi)(C) For each glycoldehydrator that has an annual average daily naturalgas throughput greater than or equal to 0.4million standard cubic feet per day, if any emissions are vented to a flare or regenerator firebox/fire tubes, annualN2O emissions, in metric tons N2O, for the dehydrator.1Dehydrators §98.236(e)(1)(xvii) For each glycol dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4million standard cubic feet per day, whether any dehydrator emissions are vented to the atmosphere without beingrouted to a flare or regenerator firebox.1Dehydrators §98.236(e)(1)(xvii)(A) For each glycoldehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4million standard cubic feet per day, if any emissions are not routed to a flare or regenerator firebox/fire tubes,annual CO2emissions, in metric tons CO2, for the dehydrator when not venting to a flare orregeneratorfirebox/fire tubes.1Dehydrators §98.236(e)(1)(xvii)(B) For each glycoldehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4million standard cubic feet per day, if any emissions are not routed to a flare or regenerator firebox/fire tubes,annual CH4emissions, in metric tons CH4, for the dehydrator when not venting to a flare orregeneratorfirebox/fire tubes.1Dehydrators §98.236(e)(1)(xviii) For each glycol dehydrator that has an annual average daily naturalgas throughput greater than or equal to 0.4million standard cubic feet per day, name of the county that best represents the equipment supplying gas to thedehydrator.1Dehydrators §98.236(e)(2)(i) The total number of glycol dehydrators at the facility with an annual average daily natural gas throughput less than0.4 million standard cubic feet per day at the facility.1Dehydrators §98.236(e)(2)(ii) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, the total numberof dehydrators at the facility that vented to a vapor recovery device.1Dehydrators §98.236(e)(2)(iii) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, the number ofdehydrators venting to a control device other thana vapor recovery device or a flare or regenerator firebox/firetubes.1Dehydrators §98.236(e)(2)(iv) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, whether anyglycol dehydrator emissions are vented to a flare or regenerator firebox/fire tubes.1Dehydrators §98.236(e)(2)(iv)(A) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, the total numberof dehydrators venting to a flare or regenerator firebox/fire tubes.1Dehydrators §98.236(e)(2)(iv)(B) Annual CO2emissions, in metric tons CO2, for the glycol dehydrators with an annual averagedaily natural gasthroughput less than 0.4 MMscfd vented to a flare or regenerator firebox/fire tubes.1Dehydrators §98.236(e)(2)(iv)(C) Annual CH4emissions, in metric tons CH4, for the glycol dehydrators with an annual averagedaily natural gasthroughput less than 0.4 MMscfd vented to a flare or regenerator firebox/fire tubes.1Dehydrators §98.236(e)(2)(iv)(D) Annual N2O emissions, in metric tons N2O, for the glycol dehydrators with an annual average daily natural gasthroughput less than 0.4 MMscfd vented to a flare or regenerator firebox/fire tubes.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionDehydrators §98.236(e)(2)(v)(A) Annual CO2emissions in metric tons CO2, for emissions from all dehydrators with an annualaverage daily naturalgas throughput less than 0.4 MMscfd that were not vented to a flare or regenerator firebox/fire tubes,whereemissions are added together for all such dehydrators.1Dehydrators §98.236(e)(2)(v)(B) Annual CH4emissions in metric tons CH4, for emissions from all dehydrators with an annualaverage daily naturalgas throughput less than 0.4 MMscfd that were not vented to a flare or regenerator firebox/fire tubes,whereemissions are added together for all such dehydrators.1Dehydrators §98.236(e)(3)(i) For dehydrators thatuse desiccant, the total number of dehydrators at the facility. 1Dehydrators §98.236(e)(3)(i) For dehydrators thatuse desiccant, the total number of dehydrators venting to a vapor recovery device. 1Dehydrators §98.236(e)(3)(i) For dehydrators thatuse desiccant, the number of dehydrators venting toa control device other than a vaporrecovery device or a flare or regenerator firebox/fire tubes.1Dehydrators §98.236(e)(3)(i) For dehydrators thatuse desiccant, the total number of dehydrators venting to a flare or regenerator firebox/firetubes.1Dehydrators §98.236(e)(3)(i) Annual CO2emissions, in metric tons CO2, for emissions from all desiccant dehydrators venting to a flare orregenerator firebox/fire tubes.1Dehydrators §98.236(e)(3)(i) Annual CH4emissions, in metric tons CH4, for emissions from all desiccant dehydrators venting to a flare orregenerator firebox/fire tubes.1Dehydrators §98.236(e)(3)(i) Annual N2O emissions, in metric tons N2O, for emissions from all desiccant dehydrators venting to a flare orregenerator firebox/fire tubes.1Dehydrators §98.236(e)(3)(ii) Annual CO2emissions, in metric tons CO2, for emissions from all desiccant dehydrators thatare not venting to aflare or regenerator firebox/fire tubes, summing for all such dehydrators.1Dehydrators §98.236(e)(3)(iii) Annual CH4emissions, in metric tons CH4, for emissions from all desiccant dehydrators thatare not venting to aflare or regenerator firebox/fire tubes, summing for all such dehydrators.1Liquids Unloading §98.236(f)(1)(ii) A list of the well ID numbers associated with each sub-basin and well tubing diameter and pressure group ID forwhich Calculation Method 1 was used to calculate natural gas emissions from well venting for liquids unloading.1Liquids Unloading §98.236(f)(2)(i) A list of the well ID numbers associated with each sub-basin for which Calculation Method 2 or 3 was used tocalculate natural gas emissions from well venting for liquids unloading.1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g) Whether the facility had any well completions or workovers with hydraulic fracturing in thecalendar year. 1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(1) For each completion or workover and well type combination, the sub-basin ID. 1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionCompletions andWorkovers withHydraulic Fracturing -Gas and Oil Wells§98.236(g)(1) A list of the well ID numbers associated with each sub-basin that had completions or workovers with hydraulicfracturing during the calendar year.1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(2) For each sub-basin and well type combination, the well type (horizontal or vertical, gaswell or oil well). 1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(3) For each sub-basin and well type combination, the total number of completions or workovers. 1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(4) For each sub-basin and well type combination, the calculation method used.1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(i) If you used Equation W-10A to calculate annual volumetric total gas emissions for a single well in a sub-basin, thecumulative gas flowback time, in hours, from when gas is first detected until sufficient quantities are present toenable separation (“Tp,i” in Equation W-10A).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(i) If using Equation W-10A to calculate annual volumetric total gas emissions for multiple wells in a sub-basin, thecumulative gas flowback time, in hours, from when gas is first detected until sufficient quantities are present toenable separation (sum of “Tp,i” values used in Equation W-10A).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(i) If you used Equation W-10A to calculate annual volumetric total gas emissions for a single well in a sub-basin, thecumulative flowback time, in hours, after sufficient quantities are present to enable separation (“Tp,s” in EquationW-10A).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(i) If using Equation W-10A to calculate annual volumetric total gas emissions for multiple wells in a sub-basin, thecumulative flowback time, in hours, after sufficient quantities are present to enable separation (sumof “Tp,s”values used in Equation W-10A).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(ii) If you used Equation W-10A to calculate annual volumetric total gas emissions, the measured flowback rate, instandard cubic feet per hour, for each sub-basin (average of “FRs,p” values used in Equation W-12A).1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionCompletions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(ii) The well ID numbers of the wellsfor which flowback rate is measured.1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(iii)(A) If you used Equation W-12C tocalculate the average gas production rate for an oil well, the gas to oil ratio for thewell in standard cubic feet of gas per barrel of oil (“GORp” in Equation W-12C).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(5)(iii)(B) If you used Equation W-12C tocalculate the average gas production rate for an oil well, the volume of oilproduced during the first 30 days of production after completions of each newly drilled well or well workoverusing hydraulic fracturing, in barrels (“Vp” in Equation W-12C).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(6)(i) If you used Equation W-10B to calculate annual volumetric total gas emissions, the vented natural gas volume, instandard cubic feet, for each well in the sub-basin(“FVs,p” in Equation W-10B).1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(6)(ii) If you used Equation W-10B to calculate annual volumetric total gas emissions, the flow rate at the beginning ofthe period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet perhour, for each well in the sub-basin (“FRp,i” in Equation W-10B).1Completions andWorkovers withHydraulic Fracturing -Gas and Oil Wells§98.236(g)(6)(iii) If Equation W-10B was used to calculate annual volumetric total gas emissions, thewell ID number for whichvented natural gas volume was measured.1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(7) The well ID numbers of the wells forwhich flowback rate is measured.1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(8) For each sub-basin and well type combination, annual CO2emissions, in metric tons CO2. 1Completions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(9) For each sub-basin and well type combination, annual CH4emissions, in metric tons CH4. 1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionCompletions andWorkovers withHydraulic Fracturing ofOil Wells§98.236(g)(10) For each sub-basin and well type combination, if the well emissions were vented to a flare, the total N2Oemissions, in metric tons N2O.1Completions andWorkovers withoutHydraulic Fracturing§98.236(h)(1)(i) A list of the well ID numbers associated with each sub-basin for gas well completionswithout hydraulic fracturingand without flaring.1Completions andWorkovers withoutHydraulic Fracturing§98.236(h)(2)(i) A list of the well ID numbers associated with each sub-basin for gas well completionswithout hydraulic fracturingand with flaring.1Completions andWorkovers withoutHydraulic Fracturing§98.236(h)(3)(i) A list of the well ID numbers associated with each sub-basin for gas well workovers without hydraulic fracturingand without flaring.1Completions andWorkovers withoutHydraulic Fracturing§98.236(h)(4)(i) A list of the well ID numbers associated with each sub-basin for gas well workovers without hydraulic fracturingand with flaring.1Blowdown Vent Stacks §98.236(i)(1)(i) If you calculated emissions from blowdown vent stacks by equipment or event type and had only one blowdownfor a unique physical volume for an equipment or event type, the number of blowdowns in the calendar year forthe equipment or event type for that unique physical volume (“N” from Equation W-14A or Equation W-14B).1 1Blowdown Vent Stacks §98.236(i)(1)(i) If you calculated emissions from blowdown vent stacks by equipment or event type, the total number ofblowdowns in the calendar year for the equipment orevent type (the sum of equation variable “N” fromEquationW-14A or Equation W-14B, for all unique physical volumes for the equipment or event type).1 1Blowdown Vent Stacks §98.236(i)(1)(ii) If you calculated emissions from blowdown vent stacks by equipment type, annual CO2emissions for theequipment or event type, in metric tons CO2.1 1Blowdown Vent Stacks §98.236(i)(1)(iii) If you calculated emissions from blowdown vent stacks by equipment type, annual CH4emissions for theequipment or event type, in metric tons CH4.1 1Blowdown Vent Stacks §98.236(i)(2)(i) If you electto calculate emissions from blowdown vent stacks by using a flow meter according to §98.233(i)(3),annual CO2emissions from all blowdown vent stacks at the facility for which emissions were calculated usingflow meters, in metric tons CO2(the sum of all CO2mass emission values calculated according to § 98.233(i)(3),for all flow meters).1 1Blowdown Vent Stacks §98.236(i)(2)(ii) If you elect to calculate emissions from blowdown vent stacksby using a flow meter according to §98.233(i)(3),annual CH4emissions from all blowdown vent stacks at the facility for which emissions were calculated usingflow meters, in metric tons CH4, (the sum of all CH4mass emission values calculated according to § 98.233(i)(3),for all flow meters).1 1Blowdown Vent Stacks §98.236(i)(3)(i) For each state, annual CO2emission in metric tons CO2.1Blowdown Vent Stacks §98.236(i)(3)(ii) For each state, annual CH4emission in metric tons CH4.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionBlowdown Vent Stacks §98.236(i)(3)(iii) Annual number of blowdown events for each state.1Storage Tanks §98.236(j) Whether your facility sends produced oil to atmospheric tanks.1Storage Tanks §98.236(j) If any of the atmospherictanks are observed to have malfunctioning dump valves, indicate that dump valves weremalfunctioning.1Storage Tanks §98.236(j)(1)(i) If using CalculationMethod 1 or 2, the county name.1Storage Tanks §98.236(j)(1)(ii) If using Calculation Method 1 or 2, calculation method used, and nameof the software package used if usingCalculation Method 1.1Storage Tanks §98.236(j)(1)(iii) If using Calculation Method 1 or 2, the total annual oil volume fromgas-liquid separators and direct from wells ornon-separator equipment that is sent to applicableonshore production and onshore petroleum and natural gasgathering and boosting storage tanks, in barrels.1Storage Tanks §98.236(j)(1)(iv) If using Calculation Method 1 or 2, the average gas-liquid separator or non-separator equipment temperature, indegrees Fahrenheit.1Storage Tanks §98.236(j)(1)(v) If using CalculationMethod 1 or 2, the average gas-liquid separator ornon-separator equipment pressure, inpounds per square inch gauge.1Storage Tanks §98.236(j)(1)(vi) If using Calculation Method 1 or 2, the average sales oil or stabilized oil API gravity, in degrees. 1Storage Tanks §98.236(j)(1)(vii) If using Calculation Method 1 or 2, the minimum and maximum concentration (mole fraction) of CO2in flash gasfrom storage tanks.1Storage Tanks §98.236(j)(1)(viii) If using Calculation Method 1 or 2, the minimum and maximum concentration (mole fraction) of CH4in flash gasfrom storage tanks.1Storage Tanks §98.236(j)(1)(x) If using CalculationMethod 1 or 2, the number of atmospheric tanks.1Storage Tanks §98.236(j)(1)(xii)(A) If using Calculation Method 1 or 2, the number of atmospheric tanks that control emissions with vapor recoverysystems.1Storage Tanks §98.236(j)(1)(xii)(B) If using Calculation Method 1 or 2, if any emissions from the atmospheric tanks at your facility were controlledwith vapor recovery systems, the total CO2mass, in metric tons CO2, that was recovered during the calendar yearusing a vapor recovery system.1Storage Tanks §98.236(j)(1)(xii)(C) If using Calculation Method 1 or 2, if any emissions from the atmospheric tanks at your facility were controlledwith vapor recovery systems, the total CH4mass, in metric tons CH4, that was recovered during the calendar yearusing a vapor recovery system.1Storage Tanks §98.236(j)(1)(xii)(D) If using Calculation Method 1 or 2, if any emissions from the atmospheric tanks at your facility were controlledwith vapor recovery systems, annual CO2emissions, in metric tons CO2, from atmospheric tanks equipped withvapor recovery systems.1Storage Tanks §98.236(j)(1)(xii)(E) If using Calculation Method 1 or 2, if any emissions from the atmospheric tanks at your facility were controlledwith vapor recovery systems, annual CH4emissions, in metric tons CH4, from atmospheric tanks equipped withvapor recovery systems.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionStorage Tanks §98.236(j)(1)(xiii)(A) If using Calculation Method 1 or 2, the number of atmospheric tanks that vented gas directly to the atmospherewithout using a vapor recovery system or without flaring.1Storage Tanks §98.236(j)(1)(xiii)(B) If using Calculation Method 1 or 2, if any atmospheric tanks at your facility vented gas directly to the atmospherewithout using a vapor recovery system or without flaring, annual CO2emissions, in metric tons CO2, that resultedfrom venting gas directly to the atmosphere.1Storage Tanks §98.236(j)(1)(xiii)(C) If using Calculation Method 1 or 2, if any atmospheric tanks at your facility vented gas directly to the atmospherewithout using a vapor recovery system or without flaring, annual CH4emissions, in metric tons CH4, that resultedfrom venting gas directly to the atmosphere.1Storage Tanks §98.236(j)(1)(xiv)(A) If using Calculation Method 1 or 2, the number of atmospheric tanks that controlled emissions with flares. 1Storage Tanks §98.236(j)(1)(xiv)(B) If using Calculation Method 1 or 2, if you controlled emissions from any atmospheric tanks at your facility withone or more flares, annual CO2emissions, in metric tons CO2, from atmospheric tanks that controlled emissionswith one or more flares.1Storage Tanks §98.236(j)(1)(xiv)(C) If using Calculation Method 1 or 2, if you controlled emissions from any atmospheric tanks at your facility withone or more flares, annual CH4emissions, in metric tons CH4, from atmospheric tanks that controlled emissionswith one or more flares.1Storage Tanks §98.236(j)(1)(xiv)(D) If using Calculation Method 1 or 2, if you controlled emissions from any atmospheric tanks at your facility withone or more flares, annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissionswith one or more flares.1Storage Tanks §98.236(j)(2)(i)(A) If using Calculation Method 3, the total annual oil/condensate throughput that is sent to all atmospheric tanks inthe gathering and boosting facility, in barrels.1Storage Tanks §98.236(j)(2)(i)(B) If using Calculation Method 3, an estimate of the fraction of oil/condensate throughput reported in paragraph(j)(2)(i)(A) sent to atmospheric tanks in the basinthat controlled emissions with flares.1Storage Tanks §98.236(j)(2)(i)(C) If using Calculation Method 3, an estimate of the fraction of oil/condensate throughput reported in paragraph(j)(2)(i)(A) sent to atmospheric tanks in the basinthat controlled emissions with vapor recovery systems.1Storage Tanks §98.236(j)(2)(i)(D) If using Calculation Method 3, the number of atmospheric tanks in the basin. 1Storage Tanks §98.236(j)(2)(ii)(A) For each countywith atmospheric tanks whose emissions were calculated using Calculation Method 3 and that didnot control emissions with flares, county name.1Storage Tanks §98.236(j)(2)(ii)(B) If using Calculation Method 3, the number of atmospheric tanks inthe county that did not control emissions withflares, including those that have vapor recovery.1Storage Tanks §98.236(j)(2)(ii)(C) If using Calculation Method 3, annual CO2emissions, in metric tons CO2, from atmospheric tanks in the countythat did not control emissions with flares, calculated using Equation W-15 and adjusted for vapor recovery, ifapplicable.1Storage Tanks §98.236(j)(2)(ii)(D) If using Calculation Method 3, annual CH4emissions, in metric tons CH4, from atmospheric tanks in the sub-basinthat vented gas directly to the atmosphere, calculated using Equation W-15 and adjusted for vapor recovery, ifapplicable.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionStorage Tanks §98.236(j)(2)(iii)(A) For each county with atmospheric tanks whose emissions were calculated using Calculation Method 3 and thatcontrolled emissions with flares, county name.1Storage Tanks §98.236(j)(2)(iii)(B) If using Calculation Method 3, the number of atmospheric tanks inthe county that controlled emissions withflares.1Storage Tanks §98.236(j)(2)(iii)(C) If using Calculation Method 3, annual CO2emissions, in metric tons CO2, from atmospheric tanks in the countythat controlled emissions with flares, calculated using Equation W-15.1Storage Tanks §98.236(j)(2)(iii)(D) If using Calculation Method 3, annual CH4emissions, in metric tons CH4, from atmospheric tanks in the countythat controlled emissions with flares, calculated using Equation W-15.1Storage Tanks §98.236(j)(2)(iii)(E) If using Calculation Method 3, annual N2O emissions, in metric tons N2O, from atmospheric tanks in the countythat controlled emissions with flares.1Storage Tanks §98.236(j)(3)(i) The total number ofgas-liquid separators in the county whose liquid dump valves did not close properly during thecalendar year.1Storage Tanks §98.236(j)(3)(ii) If using Calculation Method 1 or 2, if the gas-liquid separator liquid dump valve did not close properly on onlyone separator in a county, the total time the dumpvalve on the gas-liquid separator did not close properly in thecalendar year, in hours (“Tn” in Equation W-16).1Storage Tanks §98.236(j)(3)(ii) If dump valves onmultiple gas-liquid separators in a county did notclose properly, the total time the dump valveson gas-liquid separators did not close properly inthe calendar year, in hours (sum of the “Tn” values used inEquation W-16).1Storage Tanks §98.236(j)(3)(iii) Annual CO2emissions, in metric tons CO2, that resulted from dump valves on gas-liquid separators in the countynot closing properly during the calendar year, calculated using Equation W-16.1Storage Tanks §98.236(j)(3)(iv) Annual CH4emissions, in metric tons CH4, that resulted from the dump valves on gas-liquidseparators in thecounty not closing properly during the calendar year, calculated using Equation W-16.1Well Testing Ventingand Flaring§98.236(l)(1)(ii) If using Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wellsand the emissions are not vented to a flare, well ID numbers for the wells tested in the calendar year.1Well Testing Ventingand Flaring§98.236(l)(2)(ii) If using Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wellsand the emissions are vented to a flare, well ID numbers for the wells tested in the calendar year.1Well Testing Ventingand Flaring§98.236(l)(3)(ii) If using Equation W-17B to calculate annual volumetric natural gas emissions at actual conditions from gas wellsand the emissions were not vented to a flare, wellID numbers for the wells tested in the calendar year.1Well Testing Ventingand Flaring§98.236(l)(4)(ii) If using Equation W-17B to calculate annual volumetric natural gas emissions at actual conditions from gas wellsand the emissions were vented to a flare, well ID numbers for the wells tested in the calendar year.1Associated Natural GasVenting and Flaring§98.236(m)(1) For each sub-basin, a list of well IDnumbers for wells for which associated gas was vented or flared. 1Associated Natural GasVenting and Flaring§98.236(m)(7)(i) A list of well ID numbers for wells for which associated gas was vented directly to the atmosphere without flaring. 1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionAssociated Natural GasVenting and Flaring§98.236(m)(8)(i) A list of well ID numbers for wells for which associated gas was flared.1Flare Stacks §98.236(n)(1) Unique name or ID for the flare stack.1Flare Stacks §98.236(n)(2) Indicate whether the flare stack has a continuous flow measurement device.1Flare Stacks §98.236(n)(3) Indicate whether the flare stack has a continuous gas composition analyzeron feed gas to the flare. 1Flare Stacks §98.236(n)(4) Volume of gas sent to the flare, in standard cubic feet (“Vs” in Equations W-19 and W-20). 1Flare Stacks §98.236(n)(5) Fraction of the feed gas sent to an un-lit flare (“Zu” in Equation W-19).1Flare Stacks §98.236(n)(6) Flare combustion efficiency, expressed as the fraction of gas combusted bya burning flare. 1Flare Stacks §98.236(n)(7) Mole fraction of CH4in the feed gas to the flare (“XCH4” in Equation W-19 ). 1Flare Stacks §98.236(n)(8) Mole fraction of CO2in the feed gas to the flare (“XCO2” in Equation W-20 ). 1Flare Stacks §98.236(n)(9) Annual CO2emissions for each flare stack, in metric tons CO2(refer to Equation W-20). 1Flare Stacks §98.236(n)(10) Annual CH4emissions for each flare stack, in metric tons CH4(refer to Equation W-19), unless a CEMS was usedto measure emissions.1Flare Stacks §98.236(n)(11) Annual N2O emissions for each flare stack, in metric tons N2O (refer to Equation W-40), unless a CEMS was usedto measure emissions.1Flare Stacks §98.236(n)(12) Whether a CEMS was used to measure emissions from the flare.1Centrifugal Compressors §98.236(o)(5)(i) Number ofcentrifugal compressors that have wet seal oil degassing vents.1Centrifugal Compressors §98.236(o)(5)(ii) Annual CO2emissions, in metric tons CO2, from centrifugal compressors with wet seal oil degassing vents 1Centrifugal Compressors §98.236(o)(5)(iii) Annual CH4emissions, in metric tons CH4, from centrifugal compressors with wet seal oil degassing vents. 1ReciprocatingCompressors§98.236(p)(5)(i) Number of reciprocating compressors.1ReciprocatingCompressors§98.236(p)(5)(ii) Annual CO2emissions, in metric tons CO2, from reciprocating compressors.1ReciprocatingCompressors§98.236(p)(5)(iii) Annual CH4emissions, in metric tons CH4, from reciprocating compressors.1Equipment Leaks byPopulation Counts§98.236(r)(1)(i)Emission source type, component type, service type,and geographic location.1Equipment Leaks byPopulation Counts§98.236(r)(1)(ii) Total number of the emission source type at the facility (“Counte” in Equation W-32A). 1Equipment Leaks byPopulation Counts§98.236(r)(1)(iii) Average estimated time that theemission source type was operational in the calendar year, in hours (“Te” inEquation W-32A).1Equipment Leaks byPopulation Counts§98.236(r)(1)(iv) Annual CO2emissions, in metric tons CO2, for the emission source by component type, service type, andgeographic location.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionEquipment Leaks byPopulation Counts§98.236(r)(1)(v) Annual CH4emissions, in metric tons CH4, for the emission source component type, service type, and geographiclocation.1Equipment Leaks byPopulation Counts§98.236(r)(3)(i) Calculation method used for equipment leaks.1Equipment Leaks byPopulation Counts§98.236(r)(3)(ii)(A) An indication of whether the facility contains the major equipment type in TableW-1B. 1Equipment Leaks byPopulation Counts§98.236(r)(3)(ii)(B) For onshore petroleum and natural gas gathering and boosting, for each major equipment type, production type(i.e., natural gas or crude oil), and geographic location combination in Table W-1B of this subpart, if the facilitydoes contain the equipment type, the count of the major equipment type.1Combustion §98.236(z)(1)(i) For external fuel combustion units with a rated heat capacity less than orequal to 5 million Btu per hour or internalfuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btuper hour (or the equivalent of 130 horsepower), thetype of combustion unit.1Combustion §98.236(z)(1)(ii) For each combustion unit type listed in §98.236(z)(1), the total number of combustion units. 1Combustion §98.236(z)(2)(i) For external fuel combustion units with a rated heat capacity greater than5 mmBtu/hr; internal fuel combustionunits that are not compressor-drivers, with a ratedheat capacity greater than 1 million Btu per hour(or theequivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers,the type of combustion unit.1Combustion §98.236(z)(2)(ii) For each combustion unit type listed in §98.236(z)(2), the type of fuel combusted. 1Combustion §98.236(z)(2)(iii) If your facility contains: external fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr;internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btuper hour (or the equivalent of 130 horsepower); orinternal fuel combustion units of any heat capacitythat arecompressor-drivers, report for each combustion unittype and fuel type combination, the quantity of fuelcombusted in the calendar year, in thousand standard cubic feet, gallons, or tons.1Combustion §98.236(z)(2)(iv) For each combustion unit type listed in §98.236(z)(2), annual CO2emissions, in metric tons CO2, calculatedaccording to §98.233(z)(1) and (2).1Combustion §98.236(z)(2)(v) For each combustion unit type listed in §98.236(z)(2), annual CH4emissions, in metric tons CH4, calculatedaccording to §98.233(z)(1) and (2).1Combustion §98.236(z)(2)(vi) For each combustion unit type listed in §98.236(z)(2), annual N2O emissions, in metric tons N2O, calculatedaccording to §98.233(z)(1) and (2).1General §98.236(aa)(1)(ii)(D) For the onshore petroleum and natural gas production segment only, a list of the well ID numbers for producingwells at the end of the calendar year.1General §98.236(aa)(1)(ii)(E) For the onshore petroleum and natural gas production segment only, a list of the well ID numbers for wellsacquired during the calendar year.1General §98.236(aa)(1)(ii)(F) For the onshore petroleum and natural gas production segment only, a list of the well ID numbers for wellsdivested during the calendar year.1Emission SourceCitation ReferenceRule Text Natural Gas Transmission Pipeline Onshore Natural Gas Gathering and Boosting Onshore Petroleum and Natural Gas ProductionGeneral §98.236(aa)(1)(ii)(G) For the onshore petroleum and natural gas production segment only, a list of the well ID numbers for wellscompleted during the calendar year.1General §98.236(aa)(1)(ii)(H) For the onshore petroleum and natural gas production segment only, a list of the well ID numbers for wellspermanently taken out of production (i.e., plugged and abandoned) during the calendar year.1General §98.236(aa)(10)(i) The quantity of gas received by the gathering and boosting facility in thecalendar year, in thousand standard cubicfeet.1General §98.236(aa)(10)(ii) The quantity of gas transported to a natural gas processing facility, a natural gas transmission pipeline, a naturalgas distribution pipeline, or another gathering andboosting facility in the calendar year, in thousand standard cubicfeet.1General §98.236(aa)(10)(iii) The quantity of all hydrocarbon liquids received by the gathering and boosting facility in the calendar year, inbarrels.1General §98.236(aa)(10)(iv) The quantity of all hydrocarbon liquids transported to a natural gas processing facility, a natural gas transmissionpipeline, a natural gas distribution pipeline, or another gathering and boosting facility in the calendar year, inbarrels.1Natural gas transmissionpipelines§98.236(aa)(11)(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubicfeet. This value may include meter corrections, butonly for the calendar year covered by the annual report.1Natural gas transmissionpipelines§98.236(aa)(11)(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year,in thousand standard cubic feet. 1Natural gas transmissionpipelines§98.236(aa)(11)(iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet. 1Natural gas transmissionpipelines§98.236(aa)(11)(iv) The quantity of natural gas transferred to third parties such as LDCs or other transmission pipelines, in thousandstandard cubic feet.1Natural gas transmissionpipelines§98.236(aa)(11)(v) The quantity of natural gas consumed by the transmission pipeline facility for operational purposes, in thousandstandard cubic feet.1Natural gas transmissionpipelines§98.236(aa)(11)(vi) The miles of transmission pipeline for each state in the facility.1